PR Newswire | Nov 5, 2020 04:16PM EST

in South Texas; Provides Three-Year Outlook

11/05 15:15 CST

EOG Resources Reports Third Quarter 2020 Results; Adds Premium Natural Gas Play in South Texas; Provides Three-Year Outlook HOUSTON, Nov. 5, 2020

HOUSTON, Nov. 5, 2020 /PRNewswire/ --

* Identified 21 Tcf Net Resource Potential and 1,250 Net Premium Locations in New South Texas Natural Gas Play * Added a Total of 1,400 Net Premium Locations to Drilling Inventory Which Now Totals 11,500 Locations * Generated $1.2 Billion Net Cash Provided by Operating Activities and Significant Free Cash Flow * Capital Expenditures 23% Below Target and Crude Oil Production 2% Above Target * Per-Unit Cash Operating Costs Below Targets * Introduced Three-Year Outlook with 70-80% Cash Flow Reinvestment

EOG Resources, Inc. (EOG) today reported a third quarter 2020 net loss of $42 million, or $0.07 per share, compared with third quarter 2019 net income of $615 million, or $1.06 per share.

Adjusted non-GAAP net income for the third quarter 2020 was $252 million, or $0.43 per share, compared with adjusted non-GAAP net income of $654 million, or $1.13 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

Third Quarter 2020 ReviewEOG continued to respond aggressively to adverse market conditions by sharply lowering operating and capital costs as well as deferring production volumes to future periods. Reductions to operating costs were offset by lower commodity prices and production volumes, resulting in lower earnings in the third quarter 2020 compared with the same prior year period. Realized crude oil prices were $40.15 per barrel in the third quarter, down 29 percent from the same prior year period, while natural gas prices declined 21 percent, to $1.68 per thousand cubic feet. These declines were partially offset by an increase in natural gas liquids prices in the third quarter to $14.34 per barrel, up 13 percent compared with the same prior year period.

Compared with the third quarter 2019, total company crude oil volumes were 19 percent lower, at 377,600 barrels of oil per day (Bopd). Natural gas liquids production was one percent lower and natural gas volumes were 13 percent lower, contributing to 14 percent lower total company daily production. EOG continued to return shut-in wells to production during the third quarter, and nearly all shut-in wells were back on production by the end of September. On average, 28,000 Bopd was shut-in during the third quarter. EOG also began initial production from approximately 100 net new wells in the third quarter, after deferring such activity earlier in the year in response to lower oil prices.

Lease and well costs declined 24 percent on a per-unit basis compared with the same prior year period, driving an overall reduction in per-unit operating costs. Most of the lease and well cost savings were based on sustainable efficiency improvements in well-site maintenance, equipment repair, managing offset completions and other production operations.

Net cash provided by operating activities was $1.2 billion. Excluding changes in working capital and certain other items, EOG generated $1.3 billion of discretionary cash flow. The company incurred total expenditures of $646 million, including $499 million of capital expenditures before acquisitions, non-cash transactions and asset retirement costs, resulting in $762 million of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

"Our operational execution continues to be excellent," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "I'm grateful to all EOG employees during these unusual times. We continue to exceed expectations by optimizing production volumes and reducing costs while maintaining our strong safety and environmental performance.

"Notably, we are not playing defense in the current challenging environment. In fact, the opposite is true: we are aggressively moving EOG forward, advancing new plays, identifying innovative solutions to lower costs and improve well productivity, sharpening our technological edge and further demonstrating our commitment to sustainability. All of this is driven from the bottom up by a decentralized organization and a unique culture. This year more than ever, we are focused on investing in our people and enhancing our culture to sustain our competitive advantage and enable EOG to play an increasingly vital role in meeting the long-term global energy needs."

New South Texas Natural Gas Play and Premium Inventory UpdateEOG has made a large natural gas resource play discovery on its Dorado prospect located in Webb County, Texas. A total of 21 trillion cubic feet (Tcf) of estimated net resource potential is contained in 700 feet of stacked pay in the Austin Chalk and Eagle Ford Shale formations. The company has identified an initial 1,250 net premium drilling locations across its 163,000 net acre position in the core of the play. EOG has drilled 17 wells in the Dorado play since January 2019, including five wells targeting the Austin Chalk and 12 wells targeting the Upper and Lower Eagle Ford.

The Austin Chalk formation has an estimated net resource potential of 9.5 Tcf of natural gas. EOG has identified 530 net premium drilling locations in the Austin Chalk. The prolific Austin Chalk wells generate rates of return that are competitive with EOG's large inventory of premium oil plays. The rates of return are supported by low cash operating costs and proximity to several natural gas markets with options for LNG and pipeline export pricing. In addition, EOG plans to apply its latest water and emissions management technology to minimize the environmental footprint of its development activities.

The five initial Austin Chalk wells produced an average of 3.5 billion cubic feet (Bcf) of natural gas per well in the first year of production, with an average lateral length of 6,600 feet per well. EOG expects to complete approximately 15 wells in the Austin Chalk in 2021. A typical Austin Chalk well is expected to recover 22 Bcf of natural gas, or 18 Bcf net after royalty, from a 9,000 foot lateral at a targeted well cost of $7.0 million per well.

The company has identified additional net resource potential of 11.5 Tcf and 720 net premium drilling locations in the Lower and Upper Eagle Ford, which underlies the Austin Chalk in the same area. Wells targeting the Eagle Ford also generate strong premium rates of return, supported by low drilling costs and shared infrastructure with the Austin Chalk wells.

The first 12 wells targeting the Eagle Ford produced an average of 2.8 Bcf of natural gas per well in the first year of production, with an average lateral length of 7,700 feet per well. A typical Eagle Ford well is expected to recover 19 Bcf of natural gas, or 16 Bcf net after royalty, from a 9,000 foot lateral at a targeted well cost of $6.5 million per well.

Including the Dorado locations, EOG added 1,400 net premium drilling locations to its undrilled premium inventory in the third quarter 2020. Taking into account wells drilled over the past year and updated location counts across its portfolio, EOG's premium inventory now totals approximately 11,500 net locations.

"Our new South Texas natural gas play is the latest example of EOG's sustainable business model of organic exploration-driven resource expansion," Thomas said. "The addition of Dorado to EOG's diverse portfolio of premium plays improves the financial profile of EOG by every measure. It also allows us to diversify capital deployment throughout the organization and across our assets. We believe this prolific new discovery represents the lowest-cost natural gas play in the U.S., which will be both operationally efficient and have a small environmental footprint. With 21 Tcf of net resource potential captured by EOG in the heart of the play, it is also one of the largest. Dorado competes today with EOG's premium oil plays, and we expect it to move rapidly into the top tier of our inventory as development unfolds. This is just the latest example of how EOG continues to organically improve."

Capital Allocation OutlookOver the next three years, EOG's goal is to continue improving reinvestment returns, lowering per-unit operating costs and generating strong free cash flow to support a growing sustainable dividend while further strengthening its balance sheet. The company anticipates the current imbalance in the global crude oil market is likely to extend into 2021, and therefore expects to maintain its crude oil production at approximately the same level as the fourth quarter 2020. Assuming a balanced crude oil market after 2021, EOG expects to reinvest 70 to 80 percent of its discretionary cash flow and generate up to 10 percent compound annual crude oil production growth in 2022 and 2023 at a $50 West Texas Intermediate crude oil price and using the company's current inventory of premium locations. At higher oil prices, EOG expects to maintain the same growth rate of up to 10 percent per year. Priorities for the allocation of additional free cash flow include sustainable dividend growth, debt reduction, the return of additional cash to shareholders and low-cost property acquisitions.

"Our new three-year outlook provides visibility into the momentum we have built the last four years since the introduction of our premium return criteria," Thomas said. "EOG's long-term strategy and capital allocation priorities remain consistent. We are focused on high-return reinvestment in our growing stable of premium plays, which continues to improve in quality and drives increasing capital efficiency. With our disciplined capital allocation, we expect free cash flow growth, which will support sustainable dividend growth and further strengthen the balance sheet. Returning additional cash to shareholders also becomes more likely as oil prices continue to recover. Altogether, this balanced strategy leverages the competitive strengths of EOG and maximizes total shareholder value."

Financial ReviewAt September 30, 2020, total debt outstanding was $5.7 billion for a debt-to-total capitalization ratio of 22 percent. Considering $3.1 billion of cash on the balance sheet at the end of the third quarter, EOG's net debt-to-total capitalization ratio was 12 percent. EOG's liquidity is further enhanced by $2.0 billion of availability under its senior unsecured revolving credit agreement as of September 30, 2020. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

EOG divested its assets in the Marcellus Shale effective September 1, 2020 for proceeds of approximately $130 million. Current production from the divested assets is approximately 40 million cubic feet of natural gas per day and there were no premium locations associated with the assets.

Third Quarter 2020 Results WebcastFriday, November 6, 2020, 9:00 a.m. Central time (10:00 a.m. Eastern time) Webcast will be available on EOG's website for one year. http://investors.eogresources.com/Investors

About EOGEOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.

Investor ContactsDavid Streit 713-571-4902Neel Panchal 713-571-4884

Media and Investor ContactKimberly Ehmer 713-571-4676

Category: Earnings

This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Because we provide these measures on a forward-looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures. Management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

* the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities; * the extent to which EOG is successful in its efforts to acquire or discover additional reserves; * the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion, operating and capital costs related to, and (iv) maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations; * the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production; * security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business; * the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation and refining facilities; * the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases; * the impact of, and changes in, government policies, laws and regulations, including any changes or other actions which may result from the recent U.S. elections and including tax laws and regulations; climate change and other environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities; * EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and drilling, completing and operating costs with respect to such properties; * the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically; * competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services; * the availability and cost of employees and other personnel, facilities, equipment, materials (such as water and tubulars) and services; * the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; * weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage and transportation facilities; * the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG; * EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements; * the extent to which EOG is successful in its completion of planned asset dispositions; * the extent and effect of any hedging activities engaged in by EOG; * the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions; * the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic; * geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates; * the use of competing energy sources and the development of alternative energy sources; * the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; * acts of war and terrorism and responses to these acts; and * the other factors described under ITEM 1A, Risk Factors, on pages 13 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2019 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

Income Statements

In thousands of USD, except per share data (Unaudited)

3Q 2020 3Q 2019 YTD 2020 YTD 2019

Operating Revenues and Other

Crude Oil and Condensate 1,394,622 2,418,989 4,074,747 7,148,258

Natural Gas Liquids 184,771 164,736 439,215 569,748

Natural Gas 183,790 269,625 535,250 874,489

Gains (Losses) on Mark-to-Market Commodity Derivative (3,978) 85,902 1,075,433 242,622 Contracts

Gathering, Processing and Marketing 538,955 1,334,450 1,940,387 4,121,490

Gains (Losses) on Asset Dispositions, Net (70,976) (523) (41,283) 3,650

Other, Net 18,300 30,276 42,801 99,470

Total 2,245,484 4,303,455 8,066,550 13,059,727

Operating Expenses

Lease and Well 227,473 348,883 802,478 1,032,455

Transportation Costs 180,257 199,365 540,281 549,988

Gathering and Processing Costs 114,790 127,549 340,039 351,487

Exploration Costs 38,413 34,540 105,373 103,386

Dry Hole Costs 12,604 24,138 13,063 28,001

Impairments 78,990 105,275 1,957,340 289,761

Marketing Costs 521,351 1,343,293 2,074,788 4,114,265

Depreciation, Depletion and Amortization 823,050 953,597 2,529,789 2,790,496

General and Administrative 124,460 135,758 370,588 364,210

Taxes Other Than Income 126,810 203,098 364,489 600,418

Total 2,248,198 3,475,496 9,098,228 10,224,467

Operating Income (Loss) (2,714) 827,959 (1,031,678) 2,835,260

Other Income, Net 3,401 9,118 17,009 23,233

Income (Loss) Before Interest Expense and Income Taxes 687 837,077 (1,014,669) 2,858,493

Interest Expense, Net 53,242 39,620 152,145 144,434

Income (Loss) Before Income Taxes (52,555) 797,457 (1,166,814) 2,714,059

Income Tax Provision (Benefit) (10,088) 182,335 (224,776) 615,670

Net Income (Loss) (42,467) 615,122 (942,038) 2,098,389

Dividends Declared per Common Share 0.3750 0.2875 1.1250 0.7950

Net Income (Loss) Per Share

Basic (0.07) 1.06 (1.63) 3.63

Diluted (0.07) 1.06 (1.63) 3.61

Average Number of Common Shares

Basic 579,055 577,839 578,740 577,498

Diluted 579,055 581,271 578,740 581,190

Wellhead Volumes and Prices

(Unaudited)

3Q 3Q % Change YTD 2020 YTD 2019 % Change 2020 2019

Crude Oil and CondensateVolumes (MBbld) ^(A)

United States 376.6 463.2 -19 % 396.6 451.2 -12 %

Trinidad 1.0 0.8 25 % 0.5 0.7 -29 %

Other International ^(B) - 0.1 -100 % 0.2 0.1 100 %

Total 377.6 464.1 -19 % 397.3 452.0 -12 %

Average Crude Oil andCondensate Prices ($/Bbl) ^(C)

United States 40.19 56.67 -29 % 37.45 57.95 -35 %

Trinidad 25.41 48.36 -47 % 26.35 47.26 -44 %

Other International ^(B) 25.29 59.87 -58 % 45.09 58.43 -23 %

Composite 40.15 56.66 -29 % 37.44 57.93 -35 %

Natural Gas LiquidsVolumes (MBbld) ^(A)

United States 140.1 141.3 -1 % 134.2 130.8 3 %

Other International ^(B) - - - -

Total 140.1 141.3 -1 % 134.2 130.8 3 %

Average Natural GasLiquids Prices ($/Bbl) ^(C)

United States 14.34 12.67 13 % 11.95 15.96 -25 %

Other International ^(B) - - - -

Composite 14.34 12.67 13 % 11.95 15.96 -25 %

Natural Gas Volumes(MMcfd) ^(A)

United States 1,008 1,079 -7 % 1,029 1,043 -1 %

Trinidad 151 260 -42 % 175 267 -34 %

Other International ^(B) 31 34 -9 % 34 36 -6 %

Total 1,190 1,373 -13 % 1,238 1,346 -8 %

Average Natural GasPrices ($/Mcf) ^(C)

United States 1.49 1.97 -25 % 1.38 2.23 -38 %

Trinidad 2.35 2.52 -7 % 2.20 2.71 -19 %

Other International ^(B) 4.73 4.25 11 % 4.45 4.29 4 %

Composite 1.68 2.13 -21 % 1.58 2.38 -34 %

Crude Oil EquivalentVolumes (MBoed) ^(D)

United States 684.7 784.3 -13 % 702.3 755.8 -7 %

Trinidad 26.2 44.1 -41 % 29.8 45.1 -34 %

Other International ^(B) 5.1 5.8 -12 % 5.7 6.2 -8 %

Total 716.0 834.2 -14 % 737.8 807.1 -9 %

Total MMBoe ^(D) 65.9 76.7 -14 % 202.2 220.3 -8 %

(A) Thousand barrels per day or million cubic feet per day, as applicable.

(B) Other International includes EOG's China and Canada operations.

Dollars per barrel or per thousand cubic feet, as applicable. Excludes the(C) impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2020).

Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and(D) natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

Balance Sheets

In thousands of USD, except share data (Unaudited)

September 30, December 31,

2020 2019

Current Assets

Cash and Cash Equivalents 3,065,556 2,027,972

Accounts Receivable, Net 1,134,346 2,001,658

Inventories 668,541 767,297

Assets from Price Risk Management Activities 18,417 1,299

Income Taxes Receivable 3,182 151,665

Other 205,015 323,448

Total 5,095,057 5,273,339

Property, Plant and Equipment

Oil and Gas Properties (Successful Efforts Method) 64,020,452 62,830,415

Other Property, Plant and Equipment 4,402,091 4,472,246

Total Property, Plant and Equipment 68,422,543 67,302,661

Less: Accumulated Depreciation, Depletion and Amortization (39,789,537) (36,938,066)

Total Property, Plant and Equipment, Net 28,633,006 30,364,595

Deferred Income Taxes 1,916 2,363

Other Assets 1,344,039 1,484,311

Total Assets 35,074,018 37,124,608

Current Liabilities

Accounts Payable 1,245,029 2,429,127

Accrued Taxes Payable 267,245 254,850

Dividends Payable 217,334 166,273

Liabilities from Price Risk Management Activities 23,486 20,194

Current Portion of Long-Term Debt 770,831 1,014,524

Current Portion of Operating Lease Liabilities 255,357 369,365

Other 240,760 232,655

Total 3,020,042 4,486,988

Long-Term Debt 4,949,902 4,160,919

Other Liabilities 2,151,092 1,789,884

Deferred Income Taxes 4,804,656 5,046,101

Commitments and Contingencies

Stockholders' Equity

Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 583,668,294Shares Issued at September 30, 2020 and 582,213,016 Shares Issued at 205,837 205,822December 31, 2019

Additional Paid in Capital 5,916,213 5,817,475

Accumulated Other Comprehensive Loss (7,930) (4,652)

Retained Earnings 14,051,197 15,648,604

Common Stock Held in Treasury, 322,591 Shares at September 30, 2020 and (16,991) (26,533)298,820 Shares at December 31, 2019

Total Stockholders' Equity 20,148,326 21,640,716

Total Liabilities and Stockholders' Equity 35,074,018 37,124,608

Cash Flows Statements

In thousands of USD (Unaudited)

3Q 2020 3Q 2019 YTD 2020 YTD 2019

Cash Flows from Operating Activities

Reconciliation of Net Income (Loss) to Net Cash Provided by Operating

Activities:

Net Income (Loss) (42,467) 615,122 (942,038) 2,098,389

Items Not Requiring (Providing) Cash

Depreciation, Depletion and Amortization 823,050 953,597 2,529,789 2,790,496

Impairments 78,990 105,275 1,957,340 289,761

Stock-Based Compensation Expenses 33,811 54,670 113,454 132,323

Deferred Income Taxes (33,311) 184,282 (241,003) 508,576

(Gains) Losses on Asset Dispositions, Net 70,976 523 41,283 (3,650)

Other, Net 1,465 (1,284) 1,636 4,155

Dry Hole Costs 12,604 24,138 13,063 28,001

Mark-to-Market Commodity Derivative Contracts

Total (Gains) Losses 3,978 (85,902) (1,075,433) (242,622)

Net Cash Received from Settlements of Commodity Derivative 275,133 108,418 998,894 139,708 Contracts

Other, Net (465) (424) (1,185) 1,215

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable (260,829) 63,891 930,628 (5,855)

Inventories 7,439 66,857 92,014 55,598

Accounts Payable (37,755) 7,400 (1,222,473) 134,253

Accrued Taxes Payable 73,482 34,767 12,395 88,047

Other Assets 161,879 (92,814) 414,857 394,573

Other Liabilities 51,664 39,791 (12,739) (18,315)

Changes in Components of Working Capital Associated with (6,091) (16,643) 276,063 (38,677) Investing and Financing Activities

Net Cash Provided by Operating Activities 1,213,553 2,061,664 3,886,545 6,355,976

Investing Cash Flows

Additions to Oil and Gas Properties (468,487) (1,420,385) (2,458,520) (4,866,882)

Additions to Other Property, Plant and Equipment (17,652) (70,469) (165,018) (187,350)

Proceeds from Sales of Assets 145,575 17,767 188,943 35,409

Changes in Components of Working Capital Associated with 6,091 16,621 (276,063) 38,677 Investing Activities

Net Cash Used in Investing Activities (334,473) (1,456,466) (2,710,658) (4,980,146)

Financing Cash Flows

Long-Term Debt Borrowings - - 1,483,852 -

Long-Term Debt Repayments - - (1,000,000) (900,000)

Dividends Paid (217,142) (166,170) (601,242) (420,851)

Treasury Stock Purchased (9,764) (13,835) (14,821) (22,238)

Proceeds from Stock Options Exercised and Employee Stock - 863 8,614 9,558 Purchase Plan

Debt Issuance Costs - (114) (2,635) (5,016)

Repayment of Finance Lease Liabilities (4,864) (3,235) (13,309) (9,638)

Changes in Components of Working Capital Associated with - 22 - - Financing Activities

Net Cash Used in Financing Activities (231,770) (182,469) (139,541) (1,348,185)

Effect of Exchange Rate Changes on Cash 1,745 (109) 1,238 (174)

Increase in Cash and Cash Equivalents 649,055 422,620 1,037,584 27,471

Cash and Cash Equivalents at Beginning of Period 2,416,501 1,160,485 2,027,972 1,555,634

Cash and Cash Equivalents at End of Period 3,065,556 1,583,105 3,065,556 1,583,105

Non-GAAP Financial Measures

To supplement the presentation of its financial results prepared in accordancewith generally accepted accounting principles in the United States of America(GAAP), EOG's quarterly earnings releases and related conference calls,accompanying investor presentation slides and presentation slides for investorconferences contain certain financial measures that are not prepared orpresented in accordance with GAAP. These non-GAAP financial measures mayinclude, but are not limited to, Adjusted Net Income (Loss), Discretionary CashFlow, Free Cash Flow, Adjusted EBITDAX, Net Debt and related statistics.

A reconciliation of each of these measures to their most directly comparableGAAP financial measure is included in the tables below and can also be found inthe "Reconciliations & Guidance" section of the "Investors" page of the EOGwebsite at www.eogresources.com.

EOG believes these measures may be useful to investors who follow the practiceof some industry analysts who make certain adjustments to GAAP measures (forexample, to exclude non-recurring items) to facilitate comparisons to others inEOG's industry, and who utilize non-GAAP measures in their calculations ofcertain statistics (for example, return on capital employed and return onequity) used to evaluate EOG's performance.

EOG believes that the non-GAAP measures presented, when viewed in combinationwith its financial and operating results prepared in accordance with GAAP,provide a more complete understanding of the factors and trends affecting thecompany's performance. EOG uses these non-GAAP measures for purposes of (i)comparing EOG's financial and operating performance with the financial andoperating performance of other companies in the industry and (ii) analyzingEOG's financial and operating performance across periods.

The non-GAAP measures presented should not be considered in isolation, andshould not be considered as a substitute for, or as an alternative to, EOG'sreported Net Income (Loss), Total Debt, Net Cash Provided by OperatingActivities and other financial results calculated in accordance with GAAP. Thenon-GAAP measures presented should be read in conjunction with EOG'sconsolidated financial statements prepared in accordance with GAAP.

In addition, because not all companies use identical calculations, EOG'spresentation of non-GAAP measures may not be comparable to, and may becalculated differently from, similarly titled measures disclosed by othercompanies, including its peer companies. EOG may also change the calculation ofone or more of its non-GAAP measures from time to time - for example, toaccount for changes in its business and operations or to more closely conformto peer company or industry analysts' practices.

Adjusted Net Income (Loss)

In thousands of USD, except per share data (Unaudited)

3Q 2020

Before Income Tax After Diluted Impact Earnings Tax Tax per Share

Reported Net Loss (GAAP) (52,555) 10,088 (42,467) (0.07)

Adjustments:

Losses on Mark-to-Market Commodity Derivative Contracts 3,978 (873) 3,105 (0.01)

Net Cash Received from Settlements of Commodity Derivative Contracts 275,133 (60,386) 214,747 0.37

Add: Losses on Asset Dispositions, Net 70,976 (15,600) 55,376 0.10

Add: Certain Impairments 26,531 (5,636) 20,895 0.04

Adjustments to Net Income (Loss) 376,618 (82,495) 294,123 0.50

Adjusted Net Income (Non-GAAP) 324,063 (72,407) 251,656 0.43

Average Number of Common Shares (GAAP)

Basic 579,055

Diluted 579,055

Average Number of Common Shares (Non-GAAP)

Basic 579,055

Diluted 580,609

3Q 2019

Before Income Tax After Diluted Impact Earnings Tax Tax per Share

Reported Net Income (GAAP) 797,457 (182,335) 615,122 1.06

Adjustments:

Gains on Mark-to-Market Commodity Derivative Contracts (85,902) 18,854 (67,048) (0.12)

Net Cash Received from Settlements of Commodity Derivative Contracts 108,418 (23,796) 84,622 0.15

Add: Losses on Asset Dispositions, Net 523 (89) 434 -

Add: Certain Impairments 27,215 (5,973) 21,242 0.04

Adjustments to Net Income (Loss) 50,254 (11,004) 39,250 0.07

Adjusted Net Income (Non-GAAP) 847,711 (193,339) 654,372 1.13

Average Number of Common Shares (GAAP)

Basic 577,839

Diluted 581,271

Average Number of Common Shares (Non-GAAP) 577,839

Basic 581,271

Diluted

Adjusted Net Income (Loss)

In thousands of USD, except per share data (Unaudited)

YTD 2020

Before Income Tax After Diluted Earnings Impact per Share Tax Tax

Reported Net Loss (GAAP) (1,166,814) 224,776 (942,038) (1.63)

Adjustments:

Gains on Mark-to-MarketCommodity Derivative (1,075,433) 236,036 (839,397) (1.45)Contracts

Net Cash Received fromSettlements of Commodity 998,894 (219,237) 779,657 1.35Derivative Contracts

Add: Losses on Asset 41,283 (9,057) 32,226 0.06Dispositions, Net

Add: Certain Impairments 1,782,014 (373,960) 1,408,054 2.43

Adjustments to Net 1,746,758 (366,218) 1,380,540 2.39Income (Loss)

Adjusted Net Income 579,944 (141,442) 438,502 0.76(Non-GAAP)

Average Number of CommonShares (GAAP)

Basic 578,740

Diluted 578,740

Average Number of CommonShares (Non-GAAP)

Basic 578,740

Diluted 580,301

YTD 2019

Before Income Tax After Diluted Impact Earnings Tax Tax per Share

Reported Net Income 2,714,059 (615,670) 2,098,389 3.61(GAAP)

Adjustments:

Gains on Mark-to-MarketCommodity Derivative (242,622) 53,251 (189,371) (0.34)Contracts

Net Cash Received fromSettlements of Commodity 139,708 (30,663) 109,045 0.19Derivative Contracts

Add: Gains on Asset (3,650) 910 (2,740) -Dispositions, Net

Add: Certain Impairments 116,249 (25,514) 90,735 0.16

Adjustments to Net 9,685 (2,016) 7,669 0.01Income (Loss)

Adjusted Net Income 2,723,744 (617,686) 2,106,058 3.62(Non-GAAP)

Average Number of CommonShares (GAAP)

Basic 577,498

Diluted 581,190

Average Number of CommonShares (Non-GAAP)

Basic 577,498

Diluted 581,190

Discretionary Cash Flow and Free Cash Flow

In thousands of USD (Unaudited)

3Q 2020 3Q 2019 YTD 2020 YTD 2019

Net Cash Provided by Operating Activities (GAAP) 1,213,553 2,061,664 3,886,545 6,355,976

Adjustments:

Exploration Costs (excluding Stock-Based Compensation Expenses) 37,380 29,374 90,346 85,250

Other Non-Current Income Taxes - Net Receivable - 33,855 112,704 179,537

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable 260,829 (63,891) (930,628) 5,855

Inventories (7,439) (66,857) (92,014) (55,598)

Accounts Payable 37,755 (7,400) 1,222,473 (134,253)

Accrued Taxes Payable (73,482) (34,767) (12,395) (88,047)

Other Assets (161,879) 92,814 (414,857) (394,573)

Other Liabilities (51,664) (39,791) 12,739 18,315

Changes in Components of Working Capital Associated with 6,091 16,643 (276,063) 38,677 Investing and Financing Activities

Discretionary Cash Flow (Non-GAAP) 1,261,144 2,021,644 3,598,850 6,011,139

Discretionary Cash Flow (Non-GAAP) - Percentage Decrease -38 % -40 %

Discretionary Cash Flow (Non-GAAP) 1,261,144 2,021,644 3,598,850 6,011,139

Less:

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) ^(a) (499,305) (1,518,019) (2,661,641) (4,846,221)

Free Cash Flow (Non-GAAP) ^(b) 761,839 503,625 937,209 1,164,918

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash CapitalExpenditures Before Acquisitions (Non-GAAP) for the three-month and nine-monthperiods ended September 30, 2020 and 2019:

Total Expenditures (GAAP) 645,534 1,629,343 3,005,723 5,394,389

Less:

Asset Retirement Costs (42,650) (90,970) (68,213) (151,551)

Non-Cash Expenditures of Other Property, Plant and Equipment - - (60) (586)

Non-Cash Acquisition Costs of Unproved Properties (80,757) (10,666) (128,488) (64,387)

Non-Cash Finance Leases - - (73,277) -

Acquisition Costs of Proved Properties (22,822) (9,688) (74,044) (331,644)

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) 499,305 1,518,019 2,661,641 4,846,221

(b) To better align the presentation of free cash flow for comparativepurposes within the industry, free cash flow excludes dividends paid (GAAP)as a reconciling item for the three-month and nine-month periods endingSeptember 30, 2020. The comparative prior periods shown have been revised toconform to this presentation.

Maintenance Capital Expenditures

The capital expenditures required to fund drilling and infrastructurerequirements to keep U.S. oil production in 2021 flat relative to anticipated4Q 2020 U.S. oil production.

Discretionary Cash Flow and Free Cash Flow

In thousands of USD (Unaudited)

FY 2019 FY 2018 FY 2017

Net Cash Provided by Operating Activities (GAAP) 8,163,180 7,768,608 4,265,336

Adjustments:

Exploration Costs (excluding Stock-Based Compensation Expenses) 113,733 123,986 122,688

Other Non-Current Income Taxes - Net (Payable) Receivable 238,711 148,993 (513,404)

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable 91,792 368,180 392,131

Inventories (90,284) 395,408 174,548

Accounts Payable (168,539) (439,347) (324,192)

Accrued Taxes Payable (40,122) 92,461 63,937

Other Assets (358,001) 125,435 658,609

Other Liabilities 56,619 (10,949) 89,871

Changes in Components of Working Capital Associated with Investing and 115,061 (301,083) (89,992) Financing Activities

Discretionary Cash Flow (Non-GAAP) 8,122,150 8,271,692 4,839,532

Discretionary Cash Flow (Non-GAAP) - Percentage Increase (Decrease) -2 % 71 % 76 %

Discretionary Cash Flow (Non-GAAP) 8,122,150 8,271,692 4,839,532

Less:

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) ^(a) (6,234,454) (6,172,950) (4,228,859)

Free Cash Flow (Non-GAAP) ^(b) 1,887,696 2,098,742 610,673

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash CapitalExpenditures Before Acquisitions (Non-GAAP) for the twelve-month periods endedDecember 31, 2019, 2018 and 2017:

Total Expenditures (GAAP) 6,900,450 6,706,359 4,612,746

Less:

Asset Retirement Costs (186,088) (69,699) (55,592)

Non-Cash Expenditures of Other Property, Plant and Equipment (2,266) (49,484) -

Non-Cash Acquisition Costs of Unproved Properties (97,704) (290,542) (255,711)

Acquisition Costs of Proved Properties (379,938) (123,684) (72,584)

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) 6,234,454 6,172,950 4,228,859

(b) To better align the presentation of free cash flow for comparative purposeswithin the industry, free cash flow excludes dividends paid (GAAP) as areconciling item for the twelve-month period ending December 31, 2019. Thecomparative prior periods shown have been revised to conform to thispresentation.

Discretionary Cash Flow and Free Cash Flow

In thousands of USD (Unaudited)

FY 2016 FY 2015 FY 2014 FY 2013 FY 2012

Net Cash Provided by Operating Activities (GAAP) 2,359,063 3,595,165 8,649,155 7,329,414 5,236,777

Adjustments:

Exploration Costs (excluding Stock-Based 104,199 124,011 157,453 134,531 159,182 Compensation Expenses)

Excess Tax Benefits from Stock-Based Compensation 29,357 26,058 99,459 55,831 67,035

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable 232,799 (641,412) (84,982) 23,613 178,683

Inventories (170,694) (58,450) 161,958 (53,402) 156,762

Accounts Payable 74,048 1,409,197 (543,630) (178,701) 17,150

Accrued Taxes Payable (92,782) (11,798) (16,486) (75,142) (78,094)

Other Assets 40,636 (118,143) 14,448 109,567 118,520

Other Liabilities 16,225 66,257 (75,420) 20,382 (36,114)

Changes in Components of Working Capital 156,102 (499,767) 103,414 51,361 (74,158) Associated with Investing and Financing Activities

Discretionary Cash Flow (Non-GAAP) 2,748,953 3,891,118 8,465,369 7,417,454 5,745,743

Discretionary Cash Flow (Non-GAAP) - Percentage -29 % -54 % 14 % 29 % Increase (Decrease)

Discretionary Cash Flow (Non-GAAP) 2,748,953 3,891,118 8,465,369 7,417,454 5,745,743

Less:

Total Cash Capital Expenditures Before Acquisitions (2,706,397) (4,682,326) (8,292,090) (7,101,791) (7,539,994) (Non-GAAP) ^(a)

Free Cash Flow (Non-GAAP) ^(b) 42,556 (791,208) 173,279 315,663 (1,794,251)

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash CapitalExpenditures Before Acquisitions (Non-GAAP) for the twelve-month periods endedDecember 31, 2016, 2015, 2014, 2013 and 2012:

Total Expenditures (GAAP) 6,554,053 5,216,413 8,631,906 7,361,457 7,753,828

Less:

Asset Retirement Costs 19,865 (53,470) (195,630) (134,445) (126,987)

Non-Cash Expenditures of Other Property, Plant (16,585) - - - (65,791) and Equipment

Non-Cash Acquisition Costs of Unproved Properties (3,101,913) - (5,085) (5,007) (20,317)

Acquisition Costs of Proved Properties (749,023) (480,617) (139,101) (120,214) (739)

Total Cash Capital Expenditures Before Acquisitions 2,706,397 4,682,326 8,292,090 7,101,791 7,539,994 (Non-GAAP)

(b) To better align the presentation of free cash flow for comparative purposeswithin the industry, the presentation of free cash flow for the comparativeprior periods shown has been revised to exclude dividends paid (GAAP) as areconciling item.

Total Expenditures

In millions of USD (Unaudited)

3Q 2020 3Q FY FY FY 2019 2019 2018 2017

Exploration and Development Drilling 378 1,173 4,951 4,935 3,132

Facilities 38 161 629 625 575

Leasehold Acquisitions 88 56 276 488 427

Property Acquisitions 23 10 380 124 73

Capitalized Interest 7 10 38 24 27

Subtotal 534 1,410 6,274 6,196 4,234

Exploration Costs 38 34 140 149 145

Dry Hole Costs 13 24 28 5 5

Exploration and Development Expenditures 585 1,468 6,442 6,350 4,384

Asset Retirement Costs 44 91 186 70 56

Total Exploration and Development Expenditures 629 1,559 6,628 6,420 4,440

Other Property, Plant and Equipment 17 70 272 286 173

Total Expenditures 646 1,629 6,900 6,706 4,613

EBITDAX and Adjusted EBITDAX

In thousands of USD (Unaudited)

3Q 2020 3Q 2019 YTD 2020 YTD 2019

Net Income (Loss) (GAAP) (42,467) 615,122 (942,038) 2,098,389

Adjustments:

Interest Expense, Net 53,242 39,620 152,145 144,434

Income Tax Provision (Benefit) (10,088) 182,335 (224,776) 615,670

Depreciation, Depletion and Amortization 823,050 953,597 2,529,789 2,790,496

Exploration Costs 38,413 34,540 105,373 103,386

Dry Hole Costs 12,604 24,138 13,063 28,001

Impairments 78,990 105,275 1,957,340 289,761

EBITDAX (Non-GAAP) 953,744 1,954,627 3,590,896 6,070,137

(Gains) Losses on MTM Commodity Derivative Contracts 3,978 (85,902) (1,075,433) (242,622)

Net Cash Received from Settlements of Commodity Derivative Contracts 275,133 108,418 998,894 139,708

(Gains) Losses on Asset Dispositions, Net 70,976 523 41,283 (3,650)

Adjusted EBITDAX (Non-GAAP) 1,303,831 1,977,666 3,555,640 5,963,573

Adjusted EBITDAX (Non-GAAP) - Percentage Decrease -34 % -40 %

Definitions

EBITDAX - Earnings Before Interest Expense, Net; Income Tax Provision(Benefit); Depreciation, Depletion and Amortization; Exploration Costs; DryHole Costs; and Impairments

Net Debt-to-Total Capitalization Ratio

In millions of USD, except ratio data (Unaudited)

September 30, June 30, March 31,

2020 2020 2020

Total Stockholders' Equity - (a) 20,148 20,388 21,471

Current and Long-Term Debt (GAAP) - (b) 5,721 5,724 5,222

Less: Cash (3,066) (2,417) (2,907)

Net Debt (Non-GAAP) - (c) 2,655 3,307 2,315

Total Capitalization (GAAP) - (a) + (b) 25,869 26,112 26,693

Total Capitalization (Non-GAAP) - (a) + (c) 22,803 23,695 23,786

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 22 % 22 % 20 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] 12 % 14 % 10 %

Net Debt-to-Total Capitalization Ratio

In millions of USD, except ratio data (Unaudited)

December 31, September 30, June 30, March 31, 2019 2019 2019 2019

Total Stockholders' Equity - (a) 21,641 21,124 20,630 19,904

Current and Long-Term Debt (GAAP) - (b) 5,175 5,177 5,179 6,081

Less: Cash (2,028) (1,583) (1,160) (1,136)

Net Debt (Non-GAAP) - (c) 3,147 3,594 4,019 4,945

Total Capitalization (GAAP) - (a) + (b) 26,816 26,301 25,809 25,985

Total Capitalization (Non-GAAP) - (a) + (c) 24,788 24,718 24,649 24,849

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 19 % 20 % 20 % 23 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] 13 % 15 % 16 % 20 %

Net Debt-to-Total Capitalization Ratio

In millions of USD, except ratio data (Unaudited)

December 31, September 30, June 30, March 31,

2018 2018 2018 2018

Total Stockholders' Equity - (a) 19,364 18,538 17,452 16,841

Current and Long-Term Debt (GAAP) - (b) 6,083 6,435 6,435 6,435

Less: Cash (1,556) (1,274) (1,008) (816)

Net Debt (Non-GAAP) - (c) 4,527 5,161 5,427 5,619

Total Capitalization (GAAP) - (a) + (b) 25,447 24,973 23,887 23,276

Total Capitalization (Non-GAAP) - (a) + (c) 23,891 23,699 22,879 22,460

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 24 % 26 % 27 % 28 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] 19 % 22 % 24 % 25 %

Net Debt-to-Total Capitalization Ratio

In millions of USD, except ratio data (Unaudited)

December 31, September 30, June 30, March 31,

2017 2017 2017 2017

Total Stockholders' Equity - (a) 16,283 13,922 13,902 13,928

Current and Long-Term Debt (GAAP) - (b) 6,387 6,387 6,987 6,987

Less: Cash (834) (846) (1,649) (1,547)

Net Debt (Non-GAAP) - (c) 5,553 5,541 5,338 5,440

Total Capitalization (GAAP) - (a) + (b) 22,670 20,309 20,889 20,915

Total Capitalization (Non-GAAP) - (a) + (c) 21,836 19,463 19,240 19,368

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 28 % 31 % 33 % 33 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] 25 % 28 % 28 % 28 %

Net Debt-to-Total Capitalization Ratio

In millions of USD, except ratio data (Unaudited)

December 31, September 30, June 30, March 31, December 31, 2016 2016 2016 2016 2015

Total Stockholders' Equity - (a) 13,982 11,798 12,057 12,405 12,943

Current and Long-Term Debt (GAAP) - (b) 6,986 6,986 6,986 6,986 6,660

Less: Cash (1,600) (1,049) (780) (668) (719)

Net Debt (Non-GAAP) - (c) 5,386 5,937 6,206 6,318 5,941

Total Capitalization (GAAP) - (a) + (b) 20,968 18,784 19,043 19,391 19,603

Total Capitalization (Non-GAAP) - (a) + (c) 19,368 17,735 18,263 18,723 18,884

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + 33 % 37 % 37 % 36 % 34 % (b)]

Net Debt-to-Total Capitalization (Non-GAAP) - (c) 28 % 33 % 34 % 34 % 31 % / [(a) + (c)]

Reserve Replacement Cost Data

In millions of USD, except reserves and ratio data (Unaudited)

2019 2018 2017 2016 2015 2014

Total Costs Incurred in Exploration and Development 6,628.2 6,419.7 4,439.4 6,445.2 4,928.3 7,904.8 Activities (GAAP)

Less: Asset Retirement Costs (186.1) (69.7) (55.6) 19.9 (53.5) (195.6)

Non-Cash Acquisition Costs of Unproved (97.7) (290.5) (255.7) (3,101.8) - - Properties

Acquisition Costs of Proved Properties (379.9) (123.7) (72.6) (749.0) (480.6) (139.1)

Total Exploration and Development Expenditures for 5,964.5 5,935.8 4,055.5 2,614.3 4,394.2 7,570.1 Drilling Only (Non-GAAP) - (a)

Total Costs Incurred in Exploration and Development 6,628.2 6,419.7 4,439.4 6,445.2 4,928.3 7,904.8 Activities (GAAP)

Less: Asset Retirement Costs (186.1) (69.7) (55.6) 19.9 (53.5) (195.6)

Non-Cash Acquisition Costs of Unproved (97.7) (290.5) (255.7) (3,101.8) - - Properties

Non-Cash Acquisition Costs of Proved Properties (52.3) (70.9) (26.2) (732.3) - -

Total Exploration and Development Expenditures 6,292.1 5,988.6 4,101.9 2,631.0 4,874.8 7,709.2 (Non-GAAP) - (b)

Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)

Revisions Due to Price - (c) (59.7) 34.8 154.0 (100.7) (573.8) 52.2

Revisions Other Than Price (0.3) (39.5) 48.0 252.9 107.2 48.4

Purchases in Place 16.8 11.6 2.3 42.3 56.2 14.4

Extensions, Discoveries and Other Additions - (d) 750.0 669.7 420.8 209.0 245.9 519.2

Total Proved Reserve Additions - (e) 706.8 676.6 625.1 403.5 (164.5) 634.2

Sales in Place (4.6) (10.8) (20.7) (167.6) (3.5) (36.3)

Net Proved Reserve Additions From All Sources 702.2 665.8 604.4 235.9 (168.0) 597.9

Production 300.9 265.0 224.4 207.1 211.2 219.1

Reserve Replacement Costs ($ / Boe)

Total Drilling, Before Revisions - (a / d) 7.95 8.86 9.64 12.51 17.87 14.58

All-in Total, Net of Revisions - (b / e) 8.90 8.85 6.56 6.52 (29.63) 12.16

All-in Total, Excluding Revisions Due to Price - 8.21 9.33 8.71 5.22 11.91 13.25 (b / ( e - c))

Definitions

$/Boe U.S. Dollars per barrel of oil equivalent

MMBoe Million barrels of oil equivalent

Financial Commodity Derivative Contracts

EOG accounts for financial commodity derivative contracts using themark-to-market accounting method.

ICE Brent Differential Basis Swap Contracts

Prices received by EOG for its crude oil production generally vary from NYMEXWTI prices due to adjustments for delivery location (basis) and otherfactors. EOG has entered into crude oil basis swap contracts in order to fixthe differential between ICE Brent pricing and pricing in Cushing, Oklahoma(ICE Brent Differential). Presented below is a comprehensive summary of EOG'sICE Brent Differential basis swap contracts through October 30, 2020. Theweighted average price differential expressed in $/Bbl represents the amountof addition to Cushing, Oklahoma, prices for the notional volumes expressed inBbld covered by the basis swap contracts.

Weighted Volume Average Price2020 (Bbld) Differential

($/Bbl)

May 2020 (CLOSED) 10,000 4.92

Houston Differential Basis Swap Contracts

EOG has also entered into crude oil basis swap contracts in order to fix thedifferential between pricing in Houston, Texas, and Cushing, Oklahoma (HoustonDifferential). Presented below is a comprehensive summary of EOG's HoustonDifferential basis swap contracts through October 30, 2020. The weightedaverage price differential expressed in $/Bbl represents the amount ofaddition to Cushing, Oklahoma, prices for the notional volumes expressed inBbld covered by the basis swap contracts.

Weighted

2020 Volume Average Price (Bbld) Differential

($/Bbl)

May 2020 (CLOSED) 10,000 1.55

Roll Differential Swap Contracts

EOG has also entered into crude oil swaps in order to fix the differential inpricing between the NYMEX calendar month average and the physical crude oildelivery month (Roll Differential). Presented below is a comprehensivesummary of EOG's Roll Differential swap contracts through October 30, 2020. The weighted average price differential expressed in $/Bbl represents theamount of net addition (reduction) to delivery month prices for the notionalvolumes expressed in Bbld covered by the swap contracts.

Weighted Volume Average Price2020 (Bbld) Differential

($/Bbl)

February 1, 2020 through June 30, 2020 (CLOSED) 10,000 0.70

July 1, 2020 through September 30, 2020 88,000 (1.16)(CLOSED)

October 1, 2020 through November 30, 2020 66,000 (1.16)(CLOSED)

December 2020 66,000 (1.16)

In May 2020, EOG entered into crude oil Roll Differential swap contracts forthe period from July 1, 2020 through September 30, 2020, with notional volumesof 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, andfor the period from October 1, 2020 through December 31, 2020, with notionalvolumes of 44,000 Bbld at a weighted average price differential of $(0.73) perBbl. These contracts partially offset certain outstanding Roll Differentialswap contracts for the same time periods and volumes at a weighted averageprice differential of $(1.16) per Bbl. EOG paid net cash of $2.6 millionthrough October 30, 2020, for the settlement of certain of these contracts andexpects to pay $0.6 million during the remainder of 2020 for the settlement ofthe remaining contracts. The offsetting contracts were excluded from the abovetable.

Crude Oil NYMEX WTI Price Swap Contracts

Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI priceswap contracts through October 30, 2020, with notional volumes expressed inBbld and prices expressed in $/Bbl.

Volume Weighted2020 (Bbld) Average Price ($/Bbl)

January 1, 2020 through March 31, 2020 (CLOSED) 200,000 59.33

April 1, 2020 through May 31, 2020 (CLOSED) 265,000 51.36

In April and May 2020, EOG entered into crude oil NYMEX WTI price swapcontracts for the period from June 1, 2020 through June 30, 2020, withnotional volumes of 265,000 Bbld at a weighted average price of $33.80 perBbl, for the period from July 1, 2020 through July 31, 2020, with notionalvolumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for theperiod from August 1, 2020 through September 30, 2020, with notional volumesof 154,000 Bbld at a weighted average price of $34.18 per Bbl and for theperiod from October 1, 2020 through December 31, 2020, with notional volumesof 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contractsoffset the remaining NYMEX WTI price swap contracts for the same time periodsand volumes at a weighted average price of $51.36 per Bbl for the period fromJune 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1,2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020through September 30, 2020 and $31.00 per Bbl for the period from October 1,2020 through December 31, 2020. EOG received net cash of $359.9 millionthrough October 30, 2020, for the settlement of certain of these contracts,and expects to receive net cash of $4.1 million during the remainder of 2020for the settlement of the remaining contracts. The offsetting contracts wereexcluded from the above table.

Crude Oil ICE Brent Price Swap Contracts

Presented below is a comprehensive summary of EOG's crude oil ICE Brent priceswap contracts through October 30, 2020, with notional volumes expressed inBbld and prices expressed in $/Bbl.

Volume Weighted2020 (Bbld) Average Price ($/Bbl)

April 2020 (CLOSED) 75,000 25.66

May 2020 (CLOSED) 35,000 26.53

Mont Belvieu Propane Price Swap Contracts

Presented below is a comprehensive summary of EOG's Mont Belvieu propane(non-TET) financial price swap contracts (Mont Belvieu Propane Price SwapContracts) through October 30, 2020, with notional volumes expressed in Bbldand prices expressed in $/Bbl.

Volume Weighted2020 (Bbld) Average Price ($/Bbl)

January 1, 2020 through February 29, 2020 4,000 21.34(CLOSED)

March 1, 2020 through April 30, 2020 (CLOSED) 25,000 17.92

In April and May 2020, EOG entered into Mont Belvieu Propane Price SwapContracts for the period from May 1, 2020 through December 31, 2020, withnotional volumes of 25,000 Bbld at a weighted average price of $16.41 perBbl. These contracts offset the remaining Mont Belvieu Propane Price SwapContracts for the same time period with notional volumes of 25,000 Bbld at aweighted average price of $17.92 per Bbl. EOG received net cash of $5.7million through October 30, 2020, for the settlement of certain of thesecontracts, and expects to receive net cash of $3.5 million during theremainder of 2020 for the settlement of the remaining contracts. Theoffsetting contracts were excluded from the above table.

Natural Gas Price Swap Contracts

Presented below is a comprehensive summary of EOG's natural gas price swapcontracts through October 30, 2020, with notional volumes expressed in MMBtudand prices expressed in $/MMBtu.

Weighted Volume Average Price2021 (MMBtud) ($/MMBtu)

January 1, 2021 through December 31, 2021 500,000 2.99

Natural Gas Collar Contracts

EOG has entered into natural gas collar contracts, which establish ceiling andfloor prices for the sale of notional volumes of natural gas as specified inthe collar contracts. The collars require that EOG pay the difference betweenthe ceiling price and the NYMEX Henry Hub natural gas price for the contractmonth (Henry Hub Index Price) in the event the Henry Hub Index Price is abovethe ceiling price. The collars grant EOG the right to receive the differencebetween the floor price and the Henry Hub Index Price in the event the HenryHub Index Price is below the floor price. In March 2020, EOG executed theearly termination provision granting EOG the right to terminate certain 2020natural gas collar contracts with notional volumes of 250,000 MMBtud at aweighted average ceiling price of $2.50 per MMBtu and a weighted average floorprice of $2.00 per MMBtu for the period from April 1, 2020 through July 31,2020. EOG received net cash of $7.8 million for the settlement of thesecontracts. Presented below is a comprehensive summary of EOG's natural gascollar contracts through October 30, 2020, with notional volumes expressed inMMBtud and prices expressed in $/MMBtu.

Weighted Average Weighted Volume Average2020 (MMBtud) Ceiling Price Floor Price ($/MMBtu) ($/MMBtu)

April 1, 2020 through July 31, 2020 250,000 2.50 2.00(CLOSED)

In April 2020, EOG entered into natural gas collar contracts for the periodfrom August 1, 2020 through October 31, 2020, with notional volumes of 250,000MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 perMMBtu. These contracts offset the remaining natural gas collar contracts forthe same time period with notional volumes of 250,000 MMBtud at a ceilingprice of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. EOG receivednet cash of $1.1 million through October 30, 2020, for the settlement of thesecontracts. The offsetting contracts were excluded from the above table.

Rockies Differential Basis Swap Contracts

Prices received by EOG for its natural gas production generally vary fromNYMEX Henry Hub prices due to adjustments for delivery location (basis) andother factors. EOG has entered into natural gas basis swap contracts in orderto fix the differential between pricing in the Rocky Mountain area and NYMEXHenry Hub prices (Rockies Differential). Presented below is a comprehensivesummary of EOG's Rockies Differential basis swap contracts through October 30,2020. The weighted average price differential expressed in $/MMBtu representsthe amount of reduction to NYMEX Henry Hub prices for the notional volumesexpressed in MMBtud covered by the basis swap contracts.

Weighted Volume Average Price2020 (MMBtud) Differential ($/MMBtu)

January 1, 2020 through October 31, 2020 (CLOSED) 30,000 0.55

November 1, 2020 through December 31, 2020 30,000 0.55

HSC Differential Basis Swap Contracts

EOG has also entered into natural gas basis swap contracts in order to fix thedifferential between pricing at the Houston Ship Channel (HSC) and NYMEX HenryHub prices (HSC Differential). In March 2020, EOG executed the earlytermination provision granting EOG the right to terminate certain 2020 HSCDifferential basis swaps with notional volumes of 60,000 MMBtud at a weightedaverage price differential of $0.05 per MMBtu for the period from April 1,2020 through December 31, 2020. EOG paid net cash of $0.4 million for thesettlement of these contracts. Presented below is a comprehensive summary ofEOG's HSC Differential basis swap contracts through October 30, 2020. Theweighted average price differential expressed in $/MMBtu represents the amountof reduction to NYMEX Henry Hub prices for the notional volumes expressed inMMBtud covered by the basis swap contracts.

Weighted Volume Average Price2020 (MMBtud) Differential ($/MMBtu)

January 1, 2020 through December 31, 2020 60,000 0.05(CLOSED)

Waha Differential Basis Swap Contracts

EOG has also entered into natural gas basis swap contracts in order to fix thedifferential between pricing at the Waha Hub in West Texas and NYMEX Henry Hubprices (Waha Differential). Presented below is a comprehensive summary ofEOG's Waha Differential basis swap contracts through October 30, 2020. Theweighted average price differential expressed in $/MMBtu represents the amountof reduction to NYMEX Henry Hub prices for the notional volumes expressed inMMBtud covered by the basis swap contracts.

Weighted Volume Average Price2020 (MMBtud) Differential ($/MMBtu)

January 1, 2020 through April 30, 2020 (CLOSED) 50,000 1.40

In April 2020, EOG entered into Waha Differential basis swap contracts for theperiod from May 1, 2020 through December 31, 2020, with notional volumes of50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contractsfor the same time period with notional volumes of 50,000 MMBtud at a weightedaverage price differential of $1.40 per MMBtu. EOG paid net cash of $8.9million through October 30, 2020, for the settlement of certain of thesecontracts, and expects to pay net cash of $3.0 million during the remainder of2020 for the settlement of the remaining contracts. The offsetting contractswere excluded from the above table.

Definitions

Bbld Barrels per day

$/Bbl Dollars per barrel

ICE Intercontinental Exchange

MMBtud Million British thermal units per day

$/MMBtu Dollars per million British thermal units

NYMEX U.S. New York Mercantile Exchange

WTI West Texas Intermediate

Direct After-Tax Rate of Return

The calculation of our direct after-tax rate of return (ATROR) with respect toour capital expenditure program for a particular play or well is based on theestimated recoverable reserves ("net" to EOG's interest) for all wells in suchplay or such well (as the case may be), the estimated net present value (NPV)of the future net cash flows from such reserves (for which we utilize certainassumptions regarding future commodity prices and operating costs) and ourdirect net costs incurred in drilling or acquiring (as the case may be) suchwells or well (as the case may be). As such, our direct ATROR with respect toour capital expenditures for a particular play or well cannot be calculatedfrom our consolidated financial statements.

Direct ATROR

Based on Cash Flow and Time Value of Money

- Estimated future commodity prices and operating costs

- Costs incurred to drill, complete and equip a well, including facilities

Excludes Indirect Capital

- Gathering and Processing and other Midstream

- Land, Seismic, Geological and Geophysical

Payback ~12 Months on 100% Direct ATROR Wells

First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPVCaptured

Return on Equity / Return on Capital Employed

Based on GAAP Accrual Accounting

Includes All Indirect Capital and Growth Capital for Infrastructure

- Eagle Ford, Bakken, Permian Facilities

- Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2019 2018 2017

Net Interest Expense (GAAP) 185 245

Tax Benefit Imputed (based on 21%) (39) (51)

After-Tax Net Interest Expense (Non-GAAP) - (a) 146 194

Net Income (GAAP) - (b) 2,735 3,419

Adjustments to Net Income, Net of Tax (See Below Detail) ^(1) 158 (201)

Adjusted Net Income (Non-GAAP) - (c) 2,893 3,218

Total Stockholders' Equity - (d) 21,641 19,364 16,283

Average Total Stockholders' Equity * - (e) 20,503 17,824

Current and Long-Term Debt (GAAP) - (f) 5,175 6,083 6,387

Less: Cash (2,028) (1,556) (834)

Net Debt (Non-GAAP) - (g) 3,147 4,527 5,553

Total Capitalization (GAAP) - (d) + (f) 26,816 25,447 22,670

Total Capitalization (Non-GAAP) - (d) + (g) 24,788 23,891 21,836

Average Total Capitalization (Non-GAAP) * - (h) 24,340 22,864

Return on Capital Employed (ROCE)

GAAP Net Income - [(a) + (b)] / (h) 11.8 % 15.8 %

Non-GAAP Adjusted Net Income - [(a) + (c)] / (h) 12.5 % 14.9 %

Return on Equity (ROE)

GAAP Net Income - (b) / (e) 13.3 % 19.2 %

Non-GAAP Adjusted Net Income - (c) / (e) 14.1 % 18.1 %

* Average for the current and immediately preceding year

(1) Detail of adjustments to Net Income (GAAP):

Income Before Tax After Tax Tax Impact

Year Ended December 31, 2019

Adjustments:

Add: Mark-to-Market Commodity Derivative Contracts Impact 51 (11) 40

Add: Impairments of Certain Assets 275 (60) 215

Less: Net Gains on Asset Dispositions (124) 27 (97)

Total 202 (44) 158

Year Ended December 31, 2018

Adjustments:

Add: Mark-to-Market Commodity Derivative Contracts Impact (93) 20 (73)

Add: Impairments of Certain Assets 153 (34) 119

Less: Net Gains on Asset Dispositions (175) 38 (137)

Less: Tax Reform Impact - (110) (110)

Total (115) (86) (201)

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2017 2016 2015 2014 2013

Net Interest Expense (GAAP) 274 282 237 201 235

Tax Benefit Imputed (based on 35%) (96) (99) (83) (70) (82)

After-Tax Net Interest Expense (Non-GAAP) - (a) 178 183 154 131 153

Net Income (Loss) (GAAP) - (b) 2,583 (1,097) (4,525) 2,915 2,197

Total Stockholders' Equity - (d) 16,283 13,982 12,943 17,713 15,418

Average Total Stockholders' Equity* - (e) 15,133 13,463 15,328 16,566 14,352

Current and Long-Term Debt (GAAP) - (f) 6,387 6,986 6,655 5,906 5,909

Less: Cash (834) (1,600) (719) (2,087) (1,318)

Net Debt (Non-GAAP) - (g) 5,553 5,386 5,936 3,819 4,591

Total Capitalization (GAAP) - (d) + (f) 22,670 20,968 19,598 23,619 21,327

Total Capitalization (Non-GAAP) - (d) + (g) 21,836 19,368 18,879 21,532 20,009

Average Total Capitalization (Non-GAAP)* - (h) 20,602 19,124 20,206 20,771 19,365

Return on Capital Employed (ROCE)

GAAP Net Income (Loss) - [(a) + (b)] / (h) 13.4 % -4.8 % -21.6 % 14.7 % 12.1 %

Return on Equity (ROE)

GAAP Net Income (Loss) - (b) / (e) 17.1 % -8.1 % -29.5 % 17.6 % 15.3 %

* Average for the current and immediately preceding year

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2012 2011 2010 2009 2008

Net Interest Expense (GAAP) 214 210 130 101 52

Tax Benefit Imputed (based on 35%) (75) (74) (46) (35) (18)

After-Tax Net Interest Expense (Non-GAAP) - (a) 139 136 84 66 34

Net Income (GAAP) - (b) 570 1,091 161 547 2,437

Total Stockholders' Equity - (d) 13,285 12,641 10,232 9,998 9,015

Average Total Stockholders' Equity* - (e) 12,963 11,437 10,115 9,507 8,003

Current and Long-Term Debt (GAAP) - (f) 6,312 5,009 5,223 2,797 1,897

Less: Cash (876) (616) (789) (686) (331)

Net Debt (Non-GAAP) - (g) 5,436 4,393 4,434 2,111 1,566

Total Capitalization (GAAP) - (d) + (f) 19,597 17,650 15,455 12,795 10,912

Total Capitalization (Non-GAAP) - (d) + (g) 18,721 17,034 14,666 12,109 10,581

Average Total Capitalization (Non-GAAP)* - (h) 17,878 15,850 13,388 11,345 9,351

Return on Capital Employed (ROCE)

GAAP Net Income - [(a) + (b)] / (h) 4.0 % 7.7 % 1.8 % 5.4 % 26.4 %

Return on Equity (ROE)

GAAP Net Income - (b) / (e) 4.4 % 9.5 % 1.6 % 5.8 % 30.5 %

* Average for the current and immediately preceding year

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2007 2006 2005 2004 2003

Net Interest Expense (GAAP) 47 43 63 63 59

Tax Benefit Imputed (based on 35%) (16) (15) (22) (22) (21)

After-Tax Net Interest Expense (Non-GAAP) - (a) 31 28 41 41 38

Net Income (GAAP) - (b) 1,090 1,300 1,260 625 430

Total Stockholders' Equity - (d) 6,990 5,600 4,316 2,945 2,223

Average Total Stockholders' Equity* - (e) 6,295 4,958 3,631 2,584 1,948

Current and Long-Term Debt (GAAP) - (f) 1,185 733 985 1,078 1,109

Less: Cash (54) (218) (644) (21) (4)

Net Debt (Non-GAAP) - (g) 1,131 515 341 1,057 1,105

Total Capitalization (GAAP) - (d) + (f) 8,175 6,333 5,301 4,023 3,332

Total Capitalization (Non-GAAP) - (d) + (g) 8,121 6,115 4,657 4,002 3,328

Average Total Capitalization (Non-GAAP)* - (h) 7,118 5,386 4,330 3,665 3,068

Return on Capital Employed (ROCE)

GAAP Net Income - [(a) + (b)] / (h) 15.7 % 24.7 % 30.0 % 18.2 % 15.3 %

Return on Equity (ROE)

GAAP Net Income - (b) / (e) 17.3 % 26.2 % 34.7 % 24.2 % 22.1 %

* Average for the current and immediately preceding year

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2002 2001 2000 1999 1998

Net Interest Expense (GAAP) 60 45 61 62

Tax Benefit Imputed (based on 35%) (21) (16) (21) (22)

After-Tax Net Interest Expense (Non-GAAP) - (a) 39 29 40 40

Net Income (GAAP) - (b) 87 399 397 569

Total Stockholders' Equity - (d) 1,672 1,643 1,381 1,130 1,280

Average Total Stockholders' Equity* - (e) 1,658 1,512 1,256 1,205

Current and Long-Term Debt (GAAP) - (f) 1,145 856 859 990 1,143

Less: Cash (10) (3) (20) (25) (6)

Net Debt (Non-GAAP) - (g) 1,135 853 839 965 1,137

Total Capitalization (GAAP) - (d) + (f) 2,817 2,499 2,240 2,120 2,423

Total Capitalization (Non-GAAP) - (d) + (g) 2,807 2,496 2,220 2,095 2,417

Average Total Capitalization (Non-GAAP)* - (h) 2,652 2,358 2,158 2,256

Return on Capital Employed (ROCE)

GAAP Net Income - [(a) + (b)] / (h) 4.8 % 18.2 % 20.2 % 27.0 %

Return on Equity (ROE)

GAAP Net Income - (b) / (e) 5.2 % 26.4 % 31.6 % 47.2 %

* Average for the current and immediately preceding year

Costs per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)

1Q 2020 2Q 2020 3Q 2020 YTD 2020

Cost per Barrel of Oil Equivalent (Boe) Calculation

Volume - Thousand Barrels of Oil Equivalent - (a) 79,548 56,733 65,873 202,153

Crude Oil and Condensate 2,065,498 614,627 1,394,622 4,074,747

Natural Gas Liquids 160,535 93,909 184,771 439,215

Natural Gas 209,764 141,696 183,790 535,250

Total Wellhead Revenues - (b) 2,435,797 850,232 1,763,183 5,049,212

Operating Costs

Lease and Well 329,659 245,346 227,473 802,478

Transportation Costs 208,296 151,728 180,257 540,281

Gathering and Processing Costs 128,482 96,767 114,790 340,039

General and Administrative 114,273 131,855 124,460 370,588

Taxes Other Than Income 157,360 80,319 126,810 364,489

Interest Expense, Net 44,690 54,213 53,242 152,145

Total Cash Operating Cost (excluding DD&A and Total Exploration Costs) - (c) 982,760 760,228 827,032 2,570,020

Depreciation, Depletion and Amortization (DD&A) 1,000,060 706,679 823,050 2,529,789

Total Operating Cost (excluding Total Exploration Costs) - (d) 1,982,820 1,466,907 1,650,082 5,099,809

Exploration Costs 39,677 27,283 38,413 105,373

Dry Hole Costs 372 87 12,604 13,063

Impairments 1,572,935 305,415 78,990 1,957,340

Total Exploration Costs 1,612,984 332,785 130,007 2,075,776

Less: Certain Impairments (Non-GAAP) (1,516,316) (239,167) (26,531) (1,782,014)

Total Exploration Costs (Non-GAAP) 96,668 93,618 103,476 293,762

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) 2,079,488 1,560,525 1,753,558 5,393,571

Composite Average Wellhead Revenue per Boe - (b) / (a) 30.62 14.99 26.77 24.98

Total Cash Operating Cost per Boe (excluding DD&A and Total Exploration Costs) 12.36 13.40 12.56 12.70 - (c) / (a)

Composite Average Margin per Boe (excluding DD&A and Total Exploration 18.26 1.59 14.21 12.28 Costs) - [(b) / (a) - (c) / (a)]

Total Operating Cost per Boe (excluding Total Exploration Costs) - (d) / (a) 24.93 25.86 25.05 25.21

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(b) / 5.69 (10.87) 1.72 (0.23) (a) - (d) / (a)]

Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - 26.15 27.51 26.62 26.66 (e) / (a)

Composite Average Margin per Boe (Non-GAAP) (including Total Exploration 4.47 (12.52) 0.15 (1.68) Costs) - [(b) / (a) - (e) / (a)]

Costs per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)

2019 2018 2017

Cost per Barrel of Oil Equivalent (Boe) Calculation

Volume - Thousand Barrels of Oil Equivalent - (a) 298,565 262,516 222,251

Crude Oil and Condensate 9,612,532 9,517,440 6,256,396

Natural Gas Liquids 784,818 1,127,510 729,561

Natural Gas 1,184,095 1,301,537 921,934

Total Wellhead Revenues - (b) 11,581,445 11,946,487 7,907,891

Operating Costs

Lease and Well 1,366,993 1,282,678 1,044,847

Transportation Costs 758,300 746,876 740,352

Gathering and Processing Costs 479,102 436,973 148,775

General and Administrative 489,397 426,969 434,467

Less: Legal Settlement - Early Leasehold Termination - - (10,202)

Less: Joint Venture Transaction Costs - - (3,056)

Less: Joint Interest Billings Deemed Uncollectible - - (4,528)

General and Administrative (Non-GAAP) 489,397 426,969 416,681

Taxes Other Than Income 800,164 772,481 544,662

Interest Expense, Net 185,129 245,052 274,372

Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration 4,079,085 3,911,029 3,169,689Costs) - (c)

Depreciation, Depletion and Amortization (DD&A) 3,749,704 3,435,408 3,409,387

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d) 7,828,789 7,346,437 6,579,076

Exploration Costs 139,881 148,999 145,342

Dry Hole Costs 28,001 5,405 4,609

Impairments 517,896 347,021 479,240

Total Exploration Costs 685,778 501,425 629,191

Less: Certain Impairments (Non-GAAP) (274,974) (152,671) (261,452)

Total Exploration Costs (Non-GAAP) 410,804 348,754 367,739

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) 8,239,593 7,695,191 6,946,815

Cost per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)

2019 2018 2017

Composite Average Wellhead Revenue per Boe - (b) / (a) 38.79 45.51 35.58

Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and TotalExploration 13.66 14.90 14.25

Costs) - (c) / (a)

Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and TotalExploration 25.13 30.61 21.33 Costs) - [(b) / (a) - (c) / (a)]

Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) - 26.22 27.99 29.59 (d) / (a)

Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs)- 12.57 17.52 5.99 [(b) / (a) - (d) / (a)]

Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - 27.60 29.32 31.24 (e) / (a)

Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs)- 11.19 16.19 4.34

[(b) / (a) - (e) / (a)]

Cost per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)

2016 2015 2014

Cost per Barrel of Oil Equivalent (Boe) Calculation

Volume - Thousand Barrels of Oil Equivalent - (a) 204,929 208,862 217,073

Crude Oil and Condensate 4,317,341 4,934,562 9,742,480

Natural Gas Liquids 437,250 407,658 934,051

Natural Gas 742,152 1,061,038 1,916,386

Total Wellhead Revenues - (b) 5,496,743 6,403,258 12,592,917

Operating Costs

Lease and Well 927,452 1,182,282 1,416,413

Transportation Costs 764,106 849,319 972,176

Gathering and Processing Costs 122,901 146,156 145,800

General and Administrative 394,815 366,594 402,010

Less: Voluntary Retirement Expense (42,054) - -

Less: Acquisition Costs (5,100) - -

Less: Legal Settlement - Early Leasehold Termination - (19,355) -

General and Administrative (Non-GAAP) 347,661 347,239 402,010

Taxes Other Than Income 349,710 421,744 757,564

Interest Expense, Net 281,681 237,393 201,458

Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration 2,793,511 3,184,133 3,895,421Costs) - (c)

Depreciation, Depletion and Amortization (DD&A) 3,553,417 3,313,644 3,997,041

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d) 6,346,928 6,497,777 7,892,462

Exploration Costs 124,953 149,494 184,388

Dry Hole Costs 10,657 14,746 48,490

Impairments 620,267 6,613,546 743,575

Total Exploration Costs 755,877 6,777,786 976,453

Less: Certain Impairments (Non-GAAP) (320,617) (6,307,593) (824,312)

Total Exploration Costs (Non-GAAP) 435,260 470,193 152,141

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) 6,782,188 6,967,970 8,044,603

Cost per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)

2016 2015 2014

Composite Average Wellhead Revenue per Boe - (b) / (a) 26.82 30.66 58.01

Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and TotalExploration 13.64 15.25 17.95 Costs) - (c) / (a)

Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and TotalExploration 13.18 15.41 40.06 Costs) - [(b) / (a) - (c) / (a)]

Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) - 30.98 31.11 36.38 (d) / (a)

Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs)- (4.16) (0.45) 21.63 [(b) / (a) - (d) / (a)]

Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - 33.10 33.36 37.08 (e) / (a)

Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs)- (6.28) (2.70) 20.93 [(b) / (a) - (e) / (a)]

Quarter and Full Year Guidance

(Unaudited)

(a) Fourth Quarter and Full Year 2020 Forecast

The forecast items for the fourth quarter and full year 2020 set forth belowfor EOG Resources, Inc. (EOG) are based on current available information andexpectations as of the date of the accompanying press release. EOG undertakesno obligation, other than as required by applicable law, to update or revisethis forecast, whether as a result of new information, subsequent events,anticipated or unanticipated circumstances or otherwise. This forecast, whichshould be read in conjunction with the accompanying press release and EOG'srelated Current Report on Form 8-K filing, replaces and supersedes anypreviously issued guidance or forecast.

(b) Capital Expenditures

The forecast includes expenditures for Exploration and Development Drilling,Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs,Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludesProperty Acquisitions, Asset Retirement Costs and any Non-Cash Transactions.

(c) Benchmark Commodity Pricing

EOG bases United States and Trinidad crude oil and condensate pricedifferentials upon the West Texas Intermediate crude oil price at Cushing,Oklahoma, using the simple average of the NYMEX settlement prices for eachtrading day within the applicable calendar month.

EOG bases United States natural gas price differentials upon the natural gasprice at Henry Hub, Louisiana, using the simple average of the NYMEX settlementprices for the last three trading days of the applicable month.

Estimated Ranges for Fourth Quarter and Full Year 2020 4Q 2020 FY 2020

Daily Sales Volumes

Crude Oil and Condensate Volumes (MBbld)

United States 435.0 - 445.0 406.3 - 408.8

Trinidad 1.6 - 2.0 0.8 - 0.9

Other International 0.0 - 0.2 0.1 - 0.1

Total 436.6 - 447.2 407.2 - 409.8

Natural Gas Liquids Volumes (MBbld)

Total 140.0 - 150.0 137.2 - 139.7

Natural Gas Volumes (MMcfd)

United States 1,040 - 1,100 1,032 - 1,047

Trinidad 170 - 190 174 - 179

Other International 20 - 30 30 - 33

Total 1,230 - 1,320 1,236 - 1,259

Crude Oil Equivalent Volumes (MBoed)

United States 748.3 - 778.3 715.4 - 722.9

Trinidad 29.9 - 33.7 29.8 - 30.8

Other International 3.3 - 5.2 5.1 - 5.6

Total 781.5 - 817.2 750.3 - 759.3

Capital Expenditures ($MM) 830 - 930 3,400 3,600

Quarter and Full Year Guidance

(Unaudited)

Estimated Ranges for Fourth Quarter and Full Year 2020 4Q 2020 FY 2020

Operating Costs

Unit Costs ($/Boe)

Lease and Well 3.80 - 4.30 3.92 - 4.05

Transportation Costs 2.55 - 2.95 2.64 - 2.74

Gathering and Processing 1.75 - 1.85 1.70 - 1.72

Depreciation, Depletion and Amortization 12.20 - 12.70 12.41 - 12.54

General and Administrative 1.80 - 1.90 1.82 - 1.85

Expenses ($MM)

Exploration and Dry Hole 45 - 55 163 - 173

Impairment 100 - 150 265 - 315

Capitalized Interest 5 - 10 29 - 34

Net Interest 51 - 56 203 - 208

Taxes Other Than Income (% of Wellhead Revenue) 6.0 % - 8.0 % 6.7 % - 7.8 %

Income Taxes

Effective Rate 20 % - 25 % 16 % - 21 %

Current Tax (Benefit) / Expense ($MM) 10 - 50 (85) - (45)

Pricing - (Refer to Benchmark Commodity Pricing in text)

Crude Oil and Condensate ($/Bbl)

Differentials

United States - above (below) WTI (1.85) - 0.15 (1.07) - (0.52)

Trinidad - above (below) WTI (14.40) - (12.40) (12.52) - (11.40)

Other International - above (below) WTI (8.00) - (2.00) 2.18 - 3.68

Natural Gas Liquids

Realizations as % of WTI 34 % - 46 % 32 % - 35 %

Natural Gas ($/Mcf)

Differentials

United States - above (below) NYMEX Henry Hub (0.60) - (0.20) (0.54) - (0.43)

Realizations

Trinidad 3.15 - 3.65 2.44 - 2.59

Other International 4.35 - 4.85 4.44 - 4.54

Definitions

$/Bbl U.S. Dollars per barrel

$/Boe U.S. Dollars per barrel of oil equivalent

$/Mcf U.S. Dollars per thousand cubic feet

$MM U.S. Dollars in millions

MBbld Thousand barrels per day

MBoed Thousand barrels of oil equivalent per day

MMcfd Million cubic feet per day

NYMEX U.S. New York Mercantile Exchange

WTI West Texas Intermediate

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SOURCE EOG Resources, Inc.